US4153674A - Sulfur recovery from gases rich in H2 S and CO2 as well as COS or organic sulfur - Google Patents

Sulfur recovery from gases rich in H2 S and CO2 as well as COS or organic sulfur Download PDF

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US4153674A
US4153674A US05/858,318 US85831877A US4153674A US 4153674 A US4153674 A US 4153674A US 85831877 A US85831877 A US 85831877A US 4153674 A US4153674 A US 4153674A
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hydrogen sulfide
gas
carbon dioxide
sulfur
gases
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Jan Verloop
Rudolf C. Goetzee
Erik S. E. Werner
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Shell USA Inc
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Shell Oil Co
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C01B17/0456—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process the hydrogen sulfide-containing gas being a Claus process tail gas

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  • the invention relates to a process for working-up hydrogen sulfide-containing gases in which the sulfur constituents of the said gases are converted to elemental sulfur in a sulfur recovery unit.
  • feedstocks for sulfur recovery units are hydrogen sulfide-containing gases produced in the regeneration step of gas purification processes.
  • gas purification processes which are required in order to reduce the sulfur constituents (in most cases mainly hydrogen sulfide) of industrial gases, such as refinery gas, natural gas or synthesis gas produced by the partial combustion of hydrocarbons, to acceptably low levels prior to their further use, usually involve absorbing the sulfur components of the gases in a liquid absorbent which is then regenerated to give hydrogen sulfide-rich gases. These latter gases are then passed to a sulfur recovery unit, elemental sulfur being produced and removed. The reaction off-gases of such a unit are then preferably further treated in order to reduce the sulfur content of the gases to a very low level before the gases are finally discharged to the atmosphere.
  • sulfur recovery unit In the sulfur recovery unit the hydrogen sulfide is converted to elemental sulfur by the well-known Claus reaction. Sulfur recovery units of the Claus type or Claus plants are widely used in industry and are well-established.
  • Claus reaction refers to the reaction between hydrogen sulfide and sulfur dioxide in which elemental sulfur and water are produced.
  • sulfur recovery unit of the Claus type or “Claus plant” is meant a plant for carrying out the Claus reaction, incorporating a thermal zone in which hydrogen sulfide is partially combusted to produce sulfur dioxide in the correct proportion which then reacts with the unburned hydrogen sulfide to give sulfur and water, the sulfur then being condensed and recovered, followed by one or more catalytic zones in which the same reaction is further promoted by means of a suitable catalyst and additional sulfur is recovered.
  • the above-mentioned industrial gases often contain other sulfur constituents such as carbonyl sulfide and other organic sulfur compounds, e.g., mercaptans, which must also be removed before these gases are used. Accordingly, a suitable liquid absorbent is used which removes all sulfur constituents present.
  • the said industrial gases usually also contain carbon dioxide.
  • the liquid absorbents applied in the gas purification processes for the removal of hydrogen sulfide are generally also good absorbents for carbon dioxide.
  • a solvent is in practice used which is an efficient absorbent for carbon dioxide. Consequently, regeneration of the fat liquid absorbent yields hydrogen sulfide/carbon dioxide-containing gases which have then to be processed in the Claus plant.
  • a process for reducing the sulfur content of off gases from a Claus plant by conversion of the sulfur content of the gases to H 2 S, absorption of the H 2 S, recovery thereof and recycle to the Claus plant is the subject of U.K. Patent Specification No. 1,356,289. Said process is readily operable so long as the gases recycled to the Claus plant have a low carbon dioxide content (up to about 15% by volume) and a relatively high hydrogen sulfide content (above 50% by volume). However, if the gas fed to the Claus plant contains very high amounts of carbon dioxide, a Claus plant must be specially designed to handle such a feed. Such a plant is larger and less efficient then a plant designed for a feed with low CO 2 content.
  • industrial gases have to be purified with gas purification processes which yield hydrogen sulfide/carbon dioxide-containing gases which have even less than 20% by volume of hydrogen sulfide whereas the carbon dioxide content is above 20% by volume.
  • Such industrial gases may also result from processes for the conversion of solid fuels, such as coal, to low sulfur gas or liquid fuel.
  • the invention accordingly relates to a process for working-up hydrogen sulfide-containing gases wherein the sulfur constituents of the said gases are converted to elemental sulfur in a sulfur recovery unit of the Claus type (a Claus plant), the sulfur thus formed then being recovered from the process, and where at least one feed stream contains a high proportion of CO 2 as well as carbonyl sulfide and/or other organic sulfur compounds.
  • the process comprises the following steps:
  • step (a) the reaction off-gas of said Claus plant is passed, jointly with a hydrogen sulfide-containing gas recovered from step (d), below, which comprises a high content of carbon dioxide and in addition thereto carbonyl sulfide and/or other organic sulfur compounds, at a temperature in the range of from 180° C. to 450° C. in the presence of free hydrogen- and/or free carbon monoxide-containing gas over a sulfided Group VI and/or Group VIII metal catalyst supported on an inorganic oxidic carrier for the reduction of sulfur compounds other than hydrogen sulfide to hydrogen sulfide;
  • step (b) the reduced gas mixture obtained in step (a) is cooled and passed in an absorption zone, at a temperature below the dew point of water, through a liquid and regenerable absorbent for hydrogen sulfide at a gas velocity of 1 m/sec. or more with respect to the aerated part of the said absorption zone;
  • step (d) the regenerated absorbent obtained in step (c) is re-used in step (b) for further hydrogen sulfide absorption and the hydrogen sulfide-rich gas mixture is passed to said sulfur recovery unit for the production of elemental sulfur, optionally in combination in fresh feed gas which contains hydrogen sulfide but is low in CO 2 .
  • FIG. 1 is a schematic flow diagram of one mode of practicing this invention.
  • FIG. 2 is a schematic flow diagram of a second mode of practicing this invention.
  • reaction off-gas of a sulfur recovery unit of the Claus type still contains sulfur compounds, as the yield of recovered elemental sulfur in respect of hydrogen sulfide introduced is not completely quantitative. In addition to the sulfur compounds it may also contain some mist of elemental sulfur.
  • a typical reaction off-gas may have following composition:
  • the hydrogen sulfide-containing gas with the high carbon dioxide content and comprising carbonyl sulfide in addition thereto may further comprise other organic sulfur compounds and/or hydrogen cyanide.
  • the other organic sulfur compounds can be carbon disulfide, mercaptans and/or hydrocarbon disulfides.
  • lower alkylmercaptans and the corresponding dialkyldisulfides may be present.
  • the lower alkylmercaptans comprise alkyl groups with up to 6 carbon atoms.
  • the hydrogen sulfide-containing gas with a high carbon dioxide content generally comprises less than 30% vol. of H 2 S, between 20 and 95% vol. of CO 2 and of from 0.1 to 2.5% vol. of COS. More specifically, it may comprise 40 to 85% by vol. of CO 2 and 0.2 to 1.5% by vol. of COS, whereas its hydrogen sulfide content may be less than 22% vol. Its carbon disulfide content may vary and be in the range from 0 to 1.3% vol.% and its hydrogen cyanide content may be in the range of from 0 to 0.8% by volume.
  • Step (a) of the process according to the present invention is preferably carried out at a temperature between 200° and 350° C.
  • the mixture of the reaction off-gas of the sulfur recovery unit and the hydrogen sulfide-containing gas with the high content of carbon dioxide and carbonyl sulfide is passed over the said catalyst in the presence of at least the stoichiometric amount of free hydrogen- and/or free carbon monoxide containing gas required for the complete conversion of sulfur dioxide and elemental sulfur to hydrogen sulfide.
  • 1.3 to 2.0 times the required stoichiometric amount is applied. Higher amounts of hydrogen and/or carbon monoxide are not considered for economical reasons only.
  • step (a) A gas with a H 2 /CO ratio between 9:1 and 2:8 may suitably be used, a gas with a H 2 /CO ratio of about 4:1 being preferred.
  • the free hydrogen- and/or free carbon-monoxide-containing gas used may advantageously be a gas containing both compounds, such as town gas, water gas or synthesis gas. Pure hydrogen or carbon monoxide may also be used.
  • Suitable hydrogen-rich gases or gas mixtures are the off-gas of a catalytic reforming unit, the gas produced in a hydrogen plant or the gas obtained from a processing unit for saturated crude gases from petroleum.
  • a free hydrogen- and free carbon monoxide-containing gas may further be produced by the substoichiometric combustion of lower hydrocarbon gases such as methane, ethane, propane, butane or mixtures thereof. The production of such a gas may suitably be combined with the heating of the reaction off-gas and said hydrogen sulfide-containing gas to the required reaction temperature as set out hereinafter.
  • the reaction off-gases After having passed the last bed of the sulfur recovery unit and the relevant condenser for the recovery of elemental sulfur, the reaction off-gases normally have a temperature of from 130° C. to 170° C. For the reduction stage over the Group VI and/or Group VIII metal catalyst, however, the off-gases must have a higher temperature and therefore these off-gases have first to be heated to a temperature in excess of 170° C.
  • the reaction off-gases are preferably heated to a temperature in the range of from 180° C.
  • the increase in temperature to above 180° C. is also important in view of the presence of small amounts of elemental sulfur in the form of a mist in the reaction off-gas. This objectionable sulfur mist disappears when the temperature is raised above the dew point of sulfur. It has also been found that as a result of raising the temperature to above 180° C. the presence of elemental sulfur in the gas phase has no adverse effect on the catalytic activity of the reduction catalyst.
  • reaction off-gas and the said hydrogen sulfide-containing gas with a high carbon dioxide content together with a free-hydrogen-containing and/or free carbon monoxide-containing gas, are passed over a sulfided Group VI and/or Group VIII metal catalyst in order to reduce sulfur dioxide to hydrogen sulfide.
  • a sulfided Group VI and/or Group VIII metal catalyst in order to reduce sulfur dioxide to hydrogen sulfide.
  • elemental sulfur and carbonyl sulfide and/or other organic sulfur compounds are converted to hydrogen sulfide.
  • preferred reduction catalysts for carrying out the present invention are catalysts containing one or more of the metals: molybdenum, tungsten and chromium (of the Group VI metals), and/or one or more of the metals: cobalt, nickel and iron (of the Group VIII metals), a combination of one such Group VI metal and one such Group VIII metal being preferred.
  • the inorganic oxidic carrier may be alumina, silica, magnesia, boria, thoria, zirconia or a mixture of two or more of these compounds.
  • Most preferred reduction catalysts for use in accordance with the process of the invention are a Ni/Mo/Al 2 O 3 or a Co/Mo/Al 2 O 3 catalyst.
  • the Group VI and/or Group VIII metal catalyst is used in the sulfided form.
  • Sulfiding may be effected beforehand by means of a suitable sulfiding agent, such as a mixture of hydrogen and hydrogen sulfide containing 10-15% by volume of a sulfide. It is also possible, to sulfide the catalyst in situ by means of the reaction off-gas itself. Particularly suitable, however, is a sulfiding mixture comprising hydrogen, hydrogen sulfide and water in a ratio of 1:1:1, the sulfiding temperature being between 300 and 400° C.
  • the catalyst to be sulfided may comprise the Group VI and/or Group VIII metals as the oxide or as the element.
  • the reduced gas mixture obtained in step (a) is first cooled. Preferably it is cooled to a temperature in the range of from 6° to 60° C. More preferably cooling is effected in two steps, the first one being an indirect heat exchange and the second one a direct heat exchange with water.
  • the reduced gas mixture is contacted with the liquid and regeneratable solvent in an absorption zone.
  • a packed or a tray column may be applied.
  • a relatively high gas velocity is applied. It is preferred to use a gas velocity between 1.0 and 3.0 m/sec. with respect to the aerated part of the absorption zone. It is further preferred to apply an absorption zone having less than 20 absorption layers. If a tray column is used, the column should have less than 20 contacting valve trays. A packed column should have less than 20 theoretical plates. The use of an absorption zone having between 5 and 15 absorption layers is particularly preferred.
  • the liquid and regeneratable hydrogen-sulfide absorbent used is preferably an aqueous solution of an amine or a substituted amine.
  • Absorbents of this type are well known in the art, such as for example the alkali metal salt of dialkyl substituted amino acids, for example, potassium dimethylamino-acetate and alkanolamines. More preferably a polyalkanolamine such as diisopropanolamine is used.
  • an alkanolamine with a tertiary substituted nitrogen atom such as methyldiethanolamine or triethanolamine.
  • the alkanolamines are preferably used in aqueous solutions in a molar concentration of 0.5 to 5 and preferably 1 to 3.
  • the unabsorbed part of the reduced gas mixture which now consists mainly of nitrogen and carbon dioxide in addition to very small amounts of hydrogen and traces of hydrogen sulfide, is discharged into the atmosphere. If desired, this unabsorbed portion may also be incinerated in the usual manner before passing it to the stack.
  • the hydrogen sulfide enriched absorbent is regenerated by heating and/or stripping with steam; this produces a hydrogen sulfide enriched gas mixture and a regenerated absorbent which is re-used in step (b) for further hydrogen sulfide absorption.
  • the amount of stripping steam required can be reduced by applying aqueous solutions of alkanolamines comprising a strong acidic compound.
  • the addition of an acidic compound also results in a much lower amount of hydrogen sulfide being left in the unabsorbed part of the reduced gas mixture for a given steam amount than without the use of such acidic compound.
  • Preferably so much of this acidic compound is added that about 0.1 to 15 mole % of the alkanolamine present in the solution is present in the acid form.
  • Suitable acidic compounds are for instance ammonium salts of acetic acid, formic acid, phosphoric acid, oxalic acid and sulfuric acid, ammonium salts of the two latter acids being preferred. Instead of the salts the acids themselves may be applied in the range indicated.
  • the hydrogen sulfide-rich gas mixture which is freed in the regeneration of the absorbent, which also contains co-absorbed carbon dioxide and water, is first cooled in order to condense the water present therein. Normally, at least part of this water is recycled to the regeneration step in order to maintain the water content of the aqueous absorbent at the required level. After cooling, the hydrogen sulfide-rich gas mixture is passed to the sulfur recovery unit to recover elemental sulfur from the gas.
  • the process according to the invention is suitably used for all hydrogen sulfide-containing gases having high carbon dioxide contents and comprising carbonyl sulfide or other organic sulfides.
  • hydrogen sulfide-containing gases recovered from processes in which natural or synthesis gases containing high amounts of carbon dioxide are cleaned are very suitably used.
  • the present process is particularly advantageously applied to hydrogen sulfide-containing gases obtained from an absorption process used for the purification of gases emanating from a partial combustion process.
  • the hydrogen sulfide/carbonyl sulfide/carbon dioxide-containing gas is obtained from an absorption process which is operated under conditions such that it is non-selective or partly selective with regard to carbon dioxide.
  • the advantages of this embodiment are that both sulfur constituents and carbon dioxide are removed in this non-selective or partly selective gas purification process to give a clean product gas which may be further used, and that very little of the carbon dioxide contained in the hydrogen sulfide-containing gas which passes directly to reduction step (a) is returned via the gas recycle to the sulfur recovery unit in step (d).
  • the absorbent used in the non-selective or partly selective gas purification process can be any absorbent which readily absorbs both sulfur compounds and carbon dioxide, such as "sulfinol".
  • "Sulfinol” is an aqueous solution comprising sulfolane or a derivative thereof, together with an alkanolamine such as diisopropanolamine.
  • FIG. 1 depicts a simplified process flow scheme in which auxiliary items of equipment, such as pumps and valves, have been omitted, and wherein a single hydrogen sulfide-containing gas stream is fed to the sulfur recovery unit.
  • auxiliary items of equipment such as pumps and valves
  • FIG. 2 is also a simplified process scheme, showing two different hydrogen sulfide-containing gas streams being fed to the sulfur recovery unit.
  • a hydrogen sulfide/carbon dioxide/carbonyl sulfide-containing gas emanating from a partial combustion process is passed via line 1 to a non-selective absorption/regeneration unit 2.
  • a product gas substantially free from hydrogen sulfide, carbon dioxide and carbonyl sulfide leaves the unit via line 3 and a hydrogen sulfide/carbon dioxide-rich gas comprising also carbonyl sulfide and/or other organic sulfur compounds leaves the unit via line 5.
  • This gas mixture joins the reaction off-gas from a Claus type sulfur recovery unit 7 in line 10 and is fed together to an in-line burner 11.
  • a hydrogen and carbon monoxide-containing gas is produced by substoichiometric combustion of a hydrocarbon gas.
  • the hydrocarbon gas and the required oxygen-containing gas are fed to the burner via lines a and b.
  • burner 11 the gas mixture is mixed with the hot combustion gas and a heated gas mixture, now also containing the required hydrogen and carbon monoxide, is introduced via line 12 into reactor 13 wherein sulfur compounds other than hydrogen sulfide are converted to hydrogen sulfide over a reduction catalyst.
  • the reduced gas mixture comprising substantially no other sulfur compounds than hydrogen sulfide, leaves reactor 13 via line 14 and is cooled in a heat exchanger 15.
  • the cooled gas mixture is passed to a selective absorption/regeneration unit 16.
  • the unabsorbed components of the gas mixture consisting mainly of carbon dioxide and nitrogen, are discharged from unit 16 through line 17.
  • the unabsorbed gas components are incinerated in an incinerator 18 before being discharged to the atmosphere via line 19.
  • the hydrogen sulfide-rich gas mixture obtained from the regeneration step of the absorption/regeneration unit 16 is recycled to sulfur recovery unit 7 via line 20.
  • Sulfur recovery unit 7 is a Claus type unit which incorporates a thermal stage and an after-cooler/sulfur condenser and a number of catalytic stages with interstage coolers/sulfur condensers (not shown in the Figure).
  • the hydrogen sulfide is converted in the said unit, an oxygen-containing gas being fed via line 8 and elemental sulfur being removed via line 9.
  • the reaction off-gas leaves the sulfur recovery unit via line 10 and is treated as described above.
  • the absorbent used in the absorption/regeneration unit 2 may be the same as the one applied in the absorption/regeneration unit 16.
  • the absorbent used in the absorption/regeneration unit 2 may be the same as the one applied in the absorption/regeneration unit 16.
  • bsorbent absorbent used under operating conditions such that it is nonselective with respect to the absorption of carbon dioxide.
  • the same absorbent is, however, used under operating conditions such that the solvent is highly selective with respect to carbon dioxide.
  • FIG. 2 differs from FIG. 1 in that via line 6 a second H 2 S-containing gas stream is fed to the sulfur recovery unit.
  • a second H 2 S-containing gas stream is fed to the sulfur recovery unit.
  • Streams which mainly consist of hydrogen sulfide and contain little carbon dioxide (such as obtained from hydrodesulfurization of crude oils and other hydrocarbon oils) can be fed directly to the sulfur recovery unit by combining them with recycle stream 20, as shown.
  • the second hydrogen sulfide-containing gas stream is generally relatively small with respect to the hydrogen sulfide/carbon dioxide-rich feed stream 5.
  • the combustion furnace 18 of FIG. 1 has been omitted from FIG. 2. This will be possible by applying an alkanolamine solution in unit 16 which contains an acidic compound such as ammonium sulfate in an amount as indicated hereinbefore.
  • the gas stream 17 leaving the unit 16, mainly consisting of carbon dioxide and nitrogen, comprises such traces of hydrogen sulfide (less than 30 ppmv) that it may be vented into the atmosphere without being incinerated first.
  • 100 kmol/h of a gas stream comprising hydrogen sulfide, carbon dioxide and carbonyl sulfide, obtained from a crude oil gasification process is treated in accordance with the flow scheme of FIG. 1.
  • the gas stream is fed to the sulfinol unit at a pressure of about 20 bar and a temperature of 60° C.
  • the treated gas leaving the sulfinol unit is substantially free of hydrogen sulfide and contains only little carbonyl sulfide.
  • a hydrogen sulfide-containing gas stream with a high carbon dioxide content and containing in addition carbonyl sulfide is obtained.
  • This gas stream obtained at a rate of 3.33 kmol/h, is mixed with the reaction off-gas of the sulfur recovery unit obtained at a rate of 3.15 kmol/h and a temperature of 150° C.
  • the combined gas mixture comprising inter alia sulfur dioxide and some elemental sulfur, is heated in an in-line burner to 290° C. and fed at this temperature to the reduction reactor comprising a sulfided Co/Mo/Al 2 O 3 catalyst.
  • the convertible sulfur compounds are converted to hydrogen sulfide in the presence of hydrogen which is added to the reactor as a separate stream.
  • the gas mixture leaving the reduction reactor does not comprise any sulfur dioxide or elemental sulfur and only little carbonyl sulfide. It is cooled in two stages to 45° C.
  • the unabsorbed portion of the treated gas mixture mainly contains nitrogen and carbon dioxide and small amounts of hydrogen sulfide and carbonyl sulfide. It is fed to a catalytic incinerator operating at a temperature of 375° C. for the combustion of hydrogen sulfide and carbonyl sulfide to sulfur dioxide. After regeneration of the alkanolamine absorption solution, the hydrogen sulfide-rich gas mixture obtained is fed to the sulfur recovery unit. This gas mixture contains only 16.0% of the carbon dioxide content originally present in the feed stream to the sulfinol unit. It does not contain any carbonyl sulfide.
  • composition of the different gas streams is given in the following Table. Though the carbonyl sulfide in the gas stream leaving the absorption column is present in an amount of 400 ppmv, the total conversion of carbonyl sulfide in the process is 88.6%. The total sulfur recovered in the sulfur recovery unit is 99.3% of total sulfur present in the original gas stream to the sulfinol unit.

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US05/858,318 1976-12-07 1977-12-07 Sulfur recovery from gases rich in H2 S and CO2 as well as COS or organic sulfur Expired - Lifetime US4153674A (en)

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GB50996/76A GB1563251A (en) 1976-12-07 1976-12-07 Process for working hydrogen suphidecontaining gases
GB50996/76 1976-12-07

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AU (1) AU512247B2 (fr)
BE (1) BE861478A (fr)
BR (1) BR7708102A (fr)
CA (1) CA1098285A (fr)
DE (1) DE2754118C2 (fr)
FR (1) FR2373325B1 (fr)
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US4356161A (en) * 1981-08-24 1982-10-26 Shell Oil Company Process for reducing the total sulfur content of a high CO2 -content feed gas
US4372925A (en) * 1980-03-31 1983-02-08 Shell Oil Company Process for the removal of acid gases from gas mixtures containing methane
US4444908A (en) * 1979-04-04 1984-04-24 Union Oil Company Of California Catalyst and process for oxidizing hydrogen sulfide
US4444742A (en) * 1979-04-04 1984-04-24 Union Oil Company Of California Catalyst and process for oxidizing hydrogen sulfide
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US4552747A (en) * 1984-06-20 1985-11-12 Gaa Engineered Systems, Inc. Temperature moderation of an oxygen enriched Claus sulfur plant
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US4632818A (en) * 1984-10-03 1986-12-30 Air Products And Chemicals, Inc. Production of sulfur from an oxygen enriched claus system
US4798716A (en) * 1986-04-29 1989-01-17 Amoco Corporation Sulfur recovery plant and process using oxygen
US4826670A (en) * 1985-03-20 1989-05-02 Air Products And Chemicals, Inc. Oxygen enriched claus system with sulfuric acid injection
US4849203A (en) * 1987-12-07 1989-07-18 Amoco Corporation Sulfur recovery plant and process using oxygen
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US4892674A (en) * 1987-10-13 1990-01-09 Exxon Research And Engineering Company Addition of severely-hindered amine salts and/or aminoacids to non-hindered amine solutions for the absorption of H2 S
US4894178A (en) * 1987-10-13 1990-01-16 Exxon Research And Engineering Company Absorbent composition containing severely-hindered amine mixture for the absorption of H2 S
US4894179A (en) * 1987-10-13 1990-01-16 Exxon Research And Engineering Company Absorbent composition containing a tertiary amino azabicyclic alcohol and an amine salt
US4895670A (en) * 1987-10-13 1990-01-23 Exxon Research And Engineering Company Addition of severely-hindered aminoacids to severely-hindered amines for the absorption of H2 S
US4919912A (en) * 1985-10-18 1990-04-24 Ford, Bacon & Davis Incorporated Process for the treatment of sulfur containing gases
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US5139764A (en) * 1988-01-21 1992-08-18 Union Carbide Industrial Gases Technology Corporation Sulfur recovery process for ammonia-containing feed gas
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WO1996014135A1 (fr) * 1994-11-03 1996-05-17 Khanmamedov Tofik K Procede et equipement pour l'elimination de produits polluants dans les gaz de raffinerie
US5556606A (en) * 1994-10-07 1996-09-17 Khanmamedov; Tofik K. Method and apparatus for controlling the hydrogen sulfide concentration in the acid gas feedstock of a sulfur recovery unit
US6506349B1 (en) 1994-11-03 2003-01-14 Tofik K. Khanmamedov Process for removal of contaminants from a gas stream
US6508998B1 (en) 1996-10-28 2003-01-21 Gaa Engineered Systems, Inc. Temperature moderation of an oxygen enriched claus sulfur plant using an ejector
US20050034600A1 (en) * 2003-08-13 2005-02-17 Ravary Patrick M. Low energy regenerable SO2 scrubbing process
US20060051263A1 (en) * 2002-08-09 2006-03-09 Masahiro Harada Apparatus for treatment cos for gas produced by gasification and method for treating cos
US20060067875A1 (en) * 2002-05-03 2006-03-30 Ulrich Koss Method for purifying gas containing hydrocarbons
US20060128994A1 (en) * 2004-12-15 2006-06-15 Basf Aktiengesellschaft Use of H2S-containing offgas streams for preparing sulfur-containing products
US7172746B1 (en) 2005-12-30 2007-02-06 Gaa Engineered Systems, Inc. Temperature moderated claus process
US20090004096A1 (en) * 2004-04-22 2009-01-01 Fluor Technologies Corporation Cos-Claus Configurations and Methods
US20090050534A1 (en) * 2007-05-25 2009-02-26 Ripperger Gary Lee Process for removing sulfur from separate less reactive and more reactive fuel gas streams containing organic sulfur and light olefins
US20090050533A1 (en) * 2007-05-25 2009-02-26 Ripperger Gary Lee process for removing sulfur from a fuel gas stream additionally containing carbon dioxide and light olefins
WO2009027491A1 (fr) * 2007-08-30 2009-03-05 Shell Internationale Research Maatschappij B.V. Procédé d'extraction de sulfure d'hydrogène et de dioxyde de carbone d'un flux de gaz acide
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CN102631827A (zh) * 2012-04-11 2012-08-15 山东三维石化工程股份有限公司 与低温甲醇洗酸性气处理相结合的零排放硫回收工艺
US8444943B2 (en) 2010-04-30 2013-05-21 Black & Veatch Corporation Methods and apparatus for sulfur recovery from acid gases
US10865355B2 (en) 2013-03-14 2020-12-15 Stamicarbon B.V. COS and CS2 abatement method
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US6506349B1 (en) 1994-11-03 2003-01-14 Tofik K. Khanmamedov Process for removal of contaminants from a gas stream
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US20090004096A1 (en) * 2004-04-22 2009-01-01 Fluor Technologies Corporation Cos-Claus Configurations and Methods
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US7235697B2 (en) 2004-12-15 2007-06-26 Basf Aktiengesellschaft Use of H2S-containing offgas streams for preparing sulfur-containing products
US20060128994A1 (en) * 2004-12-15 2006-06-15 Basf Aktiengesellschaft Use of H2S-containing offgas streams for preparing sulfur-containing products
US7597871B2 (en) 2005-01-13 2009-10-06 Goar, Allison & Associates, Inc. Steam modified Claus process
US7172746B1 (en) 2005-12-30 2007-02-06 Gaa Engineered Systems, Inc. Temperature moderated claus process
US20090050533A1 (en) * 2007-05-25 2009-02-26 Ripperger Gary Lee process for removing sulfur from a fuel gas stream additionally containing carbon dioxide and light olefins
US8257673B2 (en) 2007-05-25 2012-09-04 Shell Oil Company Process for removing sulfur from separate less reactive and more reactive fuel gas streams containing organic sulfur and light olefins
US8568679B2 (en) * 2007-05-25 2013-10-29 Shell Oil Company Process for removing sulfur from a fuel gas stream additionally containing carbon dioxide and light olefins
US20090050534A1 (en) * 2007-05-25 2009-02-26 Ripperger Gary Lee Process for removing sulfur from separate less reactive and more reactive fuel gas streams containing organic sulfur and light olefins
US20100310439A1 (en) * 2007-08-30 2010-12-09 Theodorus Johannes Brok Process for removal of hydrogen sulphide and carbon dioxide from an acid gas stream
WO2009027491A1 (fr) * 2007-08-30 2009-03-05 Shell Internationale Research Maatschappij B.V. Procédé d'extraction de sulfure d'hydrogène et de dioxyde de carbone d'un flux de gaz acide
US8765086B2 (en) 2007-08-30 2014-07-01 Shell Oil Company Process for removal of hydrogen sulphide and carbon dioxide from an acid gas stream
US20110195008A1 (en) * 2008-10-06 2011-08-11 Uhde Gmbh Desulfurization process
CN102177089B (zh) * 2008-10-06 2015-04-01 犹德有限公司 脱硫的方法和装置
FR2937880A1 (fr) * 2008-11-06 2010-05-07 Inst Francais Du Petrole Procede de conversion des composes soufres presents dans un gaz acide en soufre elementaire.
US8444943B2 (en) 2010-04-30 2013-05-21 Black & Veatch Corporation Methods and apparatus for sulfur recovery from acid gases
CN102631827A (zh) * 2012-04-11 2012-08-15 山东三维石化工程股份有限公司 与低温甲醇洗酸性气处理相结合的零排放硫回收工艺
US10865355B2 (en) 2013-03-14 2020-12-15 Stamicarbon B.V. COS and CS2 abatement method
US11331623B2 (en) 2013-03-14 2022-05-17 Stamicarbon B.V. Acting Under The Name Of Mt Innovation Center COS and CS2 abatement method
WO2023072134A1 (fr) * 2021-10-26 2023-05-04 中国石油化工股份有限公司 Catalyseur et utilisation, et procédé d'élimination du sulfure de carbonyle dans le gaz naturel

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NL7713418A (nl) 1978-06-09
BE861478A (nl) 1978-06-05
PL202656A1 (pl) 1978-06-19
DE2754118C2 (de) 1986-10-23
FR2373325A1 (fr) 1978-07-07
GB1563251A (en) 1980-03-26
AU512247B2 (en) 1980-10-02
DE2754118A1 (de) 1978-06-08
JPS627960B2 (fr) 1987-02-19
RO76302A (fr) 1981-11-24
AU3122777A (en) 1979-06-14
FR2373325B1 (fr) 1982-04-23
BR7708102A (pt) 1978-09-26
NL188508B (nl) 1992-02-17
JPS5372007A (en) 1978-06-27
CA1098285A (fr) 1981-03-31
NL188508C (nl) 1992-07-16

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